Sandstone stimulation using in-situ mud acid generation

ABSTRACT

A method for stimulating production of hydrocarbons from a sandstone formation includes the steps of injecting a stimulation fluid formed from a hydrofluoric acid generating precursor and an oxidizing agent, an ammonium containing compound, and a nitrite containing compound into the sandstone formation, where one or both of the hydrofluoric acid generating precursor and the oxidizing agent comprise a degradable encapsulation. The method further includes maintaining the stimulation fluid, the ammonium containing compound, and the nitrite containing compound in the sandstone formation to initiate reaction and generate heat and nitrogen gas. Upon generation of heat and degradation of the degradable encapsulation, the hydrofluoric acid generating precursor and the oxidizing agent react to form hydrofluoric acid in-situ to dissolve silica and silicate minerals and stimulate the sandstone formation. A treatment fluid for use in stimulating sandstone formations includes the stimulation fluid, the ammonium containing compound, and the nitrite containing compound.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. Non-Provisional application Ser. No. 16/851,589 filed Apr. 17, 2020, which is a continuation-in-part of U.S. Non-Provisional application Ser. No. 16/412,962, filed May 15, 2019, which is incorporated by reference herein in its entirety.

TECHNICAL FIELD

Embodiments of the present specification generally relate to stimulating production of hydrocarbons from a sandstone formation, including liquid and gas wells.

BACKGROUND

Reserves trapped within certain low permeability formations, such as certain sandstone and carbonate formations, exhibit little or no production, and thus may be economically undesirable to develop. Well stimulation is one method that may be employed to increase the net permeability of a formation or reservoir, thereby leading to increased production from these wells that have little or no natural production.

During well stimulation operations, chemicals can be injected into the formation in a process known as well stimulation. Some stimulation techniques include: (1) injection of chemicals into the wellbore where the chemicals react with or dissolve production-limiting deposits such as clays, scale, and drilling solids; (2) injection of chemicals through the wellbore and into the formation to react with or dissolve portions of the formation, thereby creating alternative flow paths for recoverable hydrocarbons, such as with acid-fracturing or matrix-acidizing processes; and (3) injection of water or chemicals through the wellbore and into the formation at pressures that are sufficient to fracture the formation, thereby creating new or additional flow channels through which hydrocarbons can more readily move from the formation into the wellbore.

Sandstone formations can be particularly susceptible to formation damage from formation minerals such as clay and other siliceous deposits. Stimulation methods for these types of formations have typically relied on the use of acid or acid-based fluids for the treatment or stimulation due to the ability of the acid or acid-based fluid to readily dissolve both formation minerals and contaminants introduced into the wellbore/formation during drilling or remedial operations. The known prior art techniques for stimulating sandstone reservoirs typically involve the use of mineral acids, such as hydrofluoric acid (HF) and, mud acid systems which consist of a mixture of HCl and HF, and HBF₄ based systems. These systems are all corrosive and can create dangerous handling and operating conditions. Additionally, side-reactions, such as those described as being primary, secondary and tertiary, may lead to unwanted precipitation thereby creating formation damage as the treatment fluid penetrates further from the near wellbore area. Further, in many instances, the reaction of the acid with the formation is rapid, frequently instantaneous, which limits the penetration depth of the acid. Further techniques for stimulating sandstone reservoirs typically involve the use organic acids, hydrolyzable esters and acid-producing enzymes.

SUMMARY

Accordingly, there continues to be a need for alternative stimulation fluids to enhance production from a sandstone formation. This primarily refers to a conventional sandstone formation, but may also include an unconventional formation, such as a low permeability formation like a tight gas formation. Specifically, methods and compositions are needed to react deep within the formation and readily remove precipitants, such as byproducts formed as a result of side-reactions which are formed in the sandstone formation during reaction between the acid and the formation minerals.

According to one embodiment, a method for stimulating production of hydrocarbons from a sandstone formation is provided. The method includes injecting a stimulation fluid into the sandstone formation, where the stimulation fluid contains a hydrofluoric acid generating precursor and an oxidizing agent. One or both of the hydrofluoric acid generating precursor and the oxidizing agent comprise a degradable encapsulation. The method also includes injecting an ammonium containing compound into the sandstone formation and injecting a nitrite containing compound into the sandstone formation. Additionally, the method includes maintaining the stimulation fluid, the ammonium containing compound, and the nitrite containing compound in the sandstone formation. Maintaining the stimulation fluid, the ammonium containing compound, and the nitrite containing compound in the sandstone formation initiates reaction of the ammonium containing compound and the nitrite containing compound to generate heat and nitrogen gas, where upon generation of heat within the formation and degradation of the degradable encapsulation, the hydrofluoric acid generating precursor and the oxidizing agent react to form hydrofluoric acid within the sandstone formation. Finally, silica and silicate minerals are dissolved with the hydrofluoric acid to stimulate the sandstone formation.

According to another embodiment, a treatment fluid for use in stimulating sandstone formations is provided. The treatment fluid includes an ammonium-based salt, a nitrite containing compound, and a stimulation fluid. The stimulation fluid contains a hydrofluoric acid generating precursor and an oxidizing agent, where one or both of the hydrofluoric acid generating precursor and the oxidizing agent comprise a degradable encapsulation. Further, the ammonium-based salt and the nitrite containing compound are operable to react and generate heat and nitrogen gas and the hydrofluoric acid generating precursor and the oxidizing agent react are operable to react to form hydrofluoric acid.

Additional features and advantages of the described embodiments will be set forth in the detailed description which follows, and in part will be readily apparent to those skilled in the art from that description or recognized by practicing the described embodiments, including the detailed description which follows, the claims, as well as the appended drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic drawing of a wellbore used for hydraulic fracturing operations.

FIG. 2 is a schematic drawing of the propagation of microfractures within and extending from fractures produced as a result of a hydraulic fracturing procedure.

FIG. 3 is a schematic drawing of the end view of FIG. 2.

FIG. 4 is a schematic drawing of a sandstone formation subsequent to nitrogen gas creation in accordance with one or more embodiments off the present disclosure.

FIG. 5 is a graph showing the effect of initial pressure on the reaction initiation temperature.

FIG. 6 is a graph showing the effect of pH on the reaction initiation temperature.

FIG. 7 is a graph showing the generated heat and pressure downhole from the exothermic reaction of Reaction 1.

DETAILED DESCRIPTION

Reference will now be made in detail to embodiments of a method for stimulating production of hydrocarbons from a sandstone formation.

As used in this disclosure, “sandstone” refers to any formation primarily composed of silica, silicate minerals and various forms of feldspar and days. The grains of sandstone rock are traditionally sand-sized.

Provided in this disclosure are methods and compositions for the stimulation of sandstone formations to increase well productivity. The methods and compositions can, in certain embodiments, be utilized in conjunction with standard hydraulic fracturing and matrix acidizing techniques. For example, the well stimulation process can involve standard hydraulic fracturing techniques to initiate and propagate a hydraulic fracture in the referenced formation followed by introduction of the treatment fluid of the present disclosure.

The present disclosure includes a method for stimulating production of hydrocarbons from a sandstone formation. The method includes injecting an ammonium containing compound, a nitrite containing compound, and a stimulation fluid into the sandstone formation. The stimulation fluid comprises a hydrofluoric acid generating precursor and a strong oxidizing agent. The method further includes maintaining the stimulation fluid, the ammonium containing compound, and the nitrite containing compound in the sandstone formation to initiate reaction of the ammonium containing compound and the nitrite containing compound to generate heat and nitrogen gas, where upon generation of heat within the formation the hydrofluoric acid generating precursor and the strong oxidizing agent react to form hydrofluoric acid (HF) in-situ. Finally, the in-situ formed hydrofluoric acid dissolves silica and silicate minerals in the sandstone formation to stimulate the sandstone formation.

Having described the general method for generating HF within the sandstone formation and stimulating production of hydrocarbons from the same, attention is directed to the specific chemical constituents of the disclosed reaction mechanism. For each of the embodiments described in this disclosure, example hydrofluoric acid generating precursors include fluoride-containing ammonium-based salts; for example, ammonium fluoride (NH₄F) and ammonium bifluoride (NH₄HF₂). For each of the embodiments described in this disclosure, an example of a strong oxidizing agent is sodium bromate. For each of the embodiments described in this disclosure, examples of ammonium containing compounds include ammonium hydroxide, ammonium chloride, ammonium bromide, ammonium nitrate, ammonium nitrite, ammonium sulfate, and ammonium carbonate. For each of the embodiments described in this disclosure, example nitrite containing compound include sodium nitrite or potassium nitrite.

In some embodiments, the oxidizing agent comprises any agent capable of oxidizing an ammonium salt. In some embodiments, the oxidizing agent is an inorganic oxidizing agent. In some embodiments, the oxidizing agent comprises an agent selected from the group consisting of a peroxide, a persulfate salt, a permanganate salt, a bromate salt, a perbromate salt, a chlorate salt, a chlorite salt, a perchlorate salt, a hypochlorite salt, a iodate salt, a periodate salt, and mixtures thereof. In certain embodiments, the oxidizing agent is a bromate salt, for instance an alkali bromate salt. In certain embodiments, the oxidizing agent is or comprises sodium bromate. In some embodiments, the oxidizing agent is an organic oxidizing agent. In some embodiments, the oxidizing agent comprises an agent selected from the group consisting of peracetic acid and performic acid.

In some embodiments, the oxidizing agent is present in an aqueous fluid at a concentration in the range of 0.001 M up to saturation as measured at 20° C. In some embodiments, the oxidizing agent is present in an aqueous fluid at a concentration in the range of 0.05 M to 1.0 M, or 0.05 M to 0.5 M, or 0.05 M to 0.4 M, or 0.05 M to 0.3 M, or 0.1 M to 0.3 M. In some embodiments, the oxidizing agent is present in an aqueous fluid at a concentration in the range of 0.5 M to 10.0 M, or 0.5 M to 9.5 M, or 0.5 M to 9.0 M, or 1.0 M to 9.0 M, or 2.0 M to 9.0 M, or 3.0 M to 9.0 M, or 4.0 M to 9.0 M or 5.0 M to 9.0 M, or 6.0 M to 9.0 M, or 6.0 M to 8.0 M, or 6.5 M to 7.5 M. In some embodiments, the oxidizing agent is present in an aqueous fluid at a concentration in the range of 1.0 M to 4.0 M, or 1.0 M to 3.0 M, or 1.5 M to 3.0 M, or 2.0 M to 3.0 M.

In some embodiments, the oxidizing agent comprises a bromate salt such as sodium bromate and is present in an aqueous fluid at a concentration in a range of 0.001 M to 2.4 M. In some embodiments, the oxidizing agent comprises sodium bromate and is present in an aqueous fluid at a concentration in a range of 0.01 M to 2.4 M, or 0.01 M to 2.2 M, or 0.01 M to 2.0 M, or 0.01 M to 1.8 M, or 0.01 M to 1.6 M, or 0.01 M to 1.4 M, or 0.01 M to 1.2 M, or 0.01 M to 1.0 M, or 0.01 M to 0.8 M, or 0.01 M to 0.6 M, or 0.01 M to 0.4 M, or 0.01 M to 0.2 M, or 0.01 M to 0.1 M, or 0.01 M to 0.09 M, or 0.02 M to 0.09 M, or 0.03 M to 0.09 M, or 0.04 M to 0.09 M, or 0.05 M to 0.09 M, or 0.06 M to 0.08 M. In some embodiments, the oxidizing agent comprises sodium bromate and is present in an aqueous fluid at a concentration in a range of 0.1 M to 0.5 M, or 0.1 M to 0.4 M, or 0.1 M to 0.2 M, or 0.3 M to 0.4 M, or 0.15 M to 0.25 M.

In some embodiments, the oxidizing agent is characterized in that it requires a threshold temperature to react with a salt of a composition described in this application. For instance, in some embodiments, an oxidizing agent at 1 atmosphere pressure requires a threshold temperature of at least 65° C., 70° C., 75° C., 80° C., 85° C., 90° C., 95° C., 100° C., 110° C., 120° C., 130° C., or 140° C. in order to react with the hydrofluoric acid generating precursor. In some embodiments, the oxidizing agent at 1 atmosphere pressure is characterized in that it requires a threshold temperature in the range of 65° C. to 250° C. to react with the hydrofluoric acid generating precursor. In some embodiments, the oxidizing agent at 1 atmosphere pressure is characterized in that it requires a threshold temperature greater than ambient temperature to react with the hydrofluoric acid generating precursor. It will be appreciated that in the presence of accelerators such as low pH conditions, the reaction can be triggered to proceed at lower temperatures.

Examples of oxidizing agent and hydrofluoric acid generating precursor combinations for use in accordance with one or more embodiments of the present disclosure include combinations of sodium bromate in combination with ammonium fluoride, -ammonium bifluoride, ammonium hexafluorophosphate, or ammonium tetrafluoroborate.

The combination of the hydrofluoric acid generating precursor, oxidizing agent, ammonium containing compound, and nitrite containing compound form a treatment fluid. The components of the treatment fluid are provided to the sandstone formation to generate nitrogen gas, heat, and HF in-situ. In one or more embodiments, the components of the treatment fluid comprise ammonium fluoride (NH₄F) as the hydrofluoric acid generating precursor, sodium bromate (NaBrO₃) as the oxidizing agent, sodium nitrite (NaNO₂) as the nitrite containing compound, and ammonium chloride (NH₄Cl) as the ammonium containing compound. For clarity and conciseness, Reactions 1 through 3 are described using components of the treatment fluid as delineated in the previous example compositions. However, it should be understood by a person of ordinary skill in the art that compounds of similar class of reactants will generally react in a similar way as the example reaction schemes shown in Reactions 1 through 3.

A reaction between the ammonium containing compound and the nitrite containing compound generates heat and nitrogen gas. An example of such a reaction is provided in Reaction 1.

NH₄Cl+NaNO₂→NaCl+2H₂O+N₂ (gas)+ΔH (heat)  Reaction 1

In typical usage, Reaction 1 results in generation of about 225 kilocalories (Kcal) of heat per one liter (L) of reactants. Without wishing to be bound by theory, it is believed that the increased pressure from nitrogen gas generation downhole may provide additional energy to flowback the well and prevent precipitation of any reaction products of HF and sandstone.

A follow-on reaction of the hydrofluoric acid generating precursor and the oxidizing agent generates HF in-situ. However, the reaction requires heating of the reactants to at least 300° F. (149.9° C.) to proceed at a pressure of 50 pounds per square inch (PSI). It will be appreciated that the initiation temperature may be reduced with an elevation in pressure. While the temperature of the formation may be sufficient for the reaction to proceed, the heat generated in Reaction 1 provides additional thermal energy to expedite initiation of the reaction of the hydrofluoric acid generating precursor and the oxidizing agent. An example reaction is provided in Reaction 2.

12NH₄ ⁺+6BrO₃ ⁻→10H⁺+H₂+6N₂+Br₂+4Br⁻+18H₂O  Reaction 2

The reactants in the treatment fluid also may undergo an alternate reaction between the ammonium containing compound and the oxidizing agent. When the ammonium containing compound is ammonium chloride, reaction with the oxidizing agent generates hydrochloric acid (HCl). The generation of HCl in-situ assists in maintaining an acidic pH at the sandstone formation. The HCl also helps keep the reaction products soluble in the spent treatment fluid. Additionally, the reaction of the ammonium containing compound and the oxidizing agent generates additional nitrogen gas which is beneficial in providing energy to flowback the well and prevent or remove any precipitation. This reaction is captured in the generic form of Reaction 2.

In one or more embodiments, ammonium bifluoride (NH₄HF₂) may additionally be provided downhole to generate additional HF. The ammonium bifluoride reacts with HCl to generate additional HF downhole in accordance with Reaction 3 provided subsequently. The HCl may be present downhole as a product of Reaction 2. The HCl may also be provided downhole alternatively or additionally as a feed of HCl pumped from the surface.

2HCl+NH₄HF₂→NH₄Cl+2HF  Reaction 3

One or both of the hydrofluoric acid generating precursor and the oxidizing agent comprise a degradable encapsulation. In some embodiments, the oxidizing agent is provided in an encapsulated form, for instance to delay its release. Encapsulated oxidizing agents are commercially available and are known to those of ordinary skill in the art. Exemplary encapsulated oxidizing agents include sodium persulfate, potassium persulfate, sodium bromate and potassium bromate. In some embodiments, the hydrofluoric acid generating precursor is provided in an encapsulated form, for instance to delay its release. Encapsulation of one or both of the hydrofluoric acid generating precursor and the oxidizing agent prevents reaction of the oxidizing agent with the hydrofluoric acid generating precursor such that the oxidizing agent is consumed prior to reaction with the ammonium containing compound, such as reaction with NH₄Cl to generate HCl in accordance with Reaction 2.

When the methods of the present disclosure are utilized during hydraulic fracturing treatments, a synthetic sweet spot can be created, thereby stimulating production and enabling maximum enhancement of gas production. A sweet spot is generally defined in this disclosure as the area within a reservoir that represents the best production or potential for production. FIG. 1 is a schematic drawing of a wellbore used for hydraulic fracturing operations, where a fracturing fluid is injected into the wellbore 100 at a flow rate such that pressure is created inside the wellbore to cause fractures 110 in the formation. Generally, the fracture 110 produced during hydraulic fracturing can extend deep into the formation, as shown in the region of hydraulic fracturing 101. For example, as shown in FIG. 1, the fracture 110 is shown to extend into the formation to a fracture length 102. In various embodiments, this fracture length 102 can extend up to 100 meters, up to 50 meters, and up to 25 meters. Additionally, the hydraulic fracturing process can be designed such that the fractures 110 extend outward from the wellbore in multiple directions.

FIG. 2 shows the propagation of microfractures 112 within and extending from the fractures 110 produced as a result of the hydraulic fracturing procedure, thus creating sweet spots 116. Depending upon the reactants and the volume of nitrogen gas produced therefrom, the microfractures 112 can extend throughout a pseudo fracture width 118 from the fracture 110 created during hydraulic fracturing. The pseudo fracture width 118 represents the penetration depth of the microfractures 112 extending from the fracture 110. FIG. 3 similarly shows an end view of the same. The microfractures 112 may additionally be generated or cleared of formation minerals in sandstone formations with the introduction of the hydrofluoric acid generated in accordance with this disclosure.

The release of nitrogen gas within the formation during the hydraulic fracturing operation forms additional microfractures 112 within the formation. With reference to FIG. 4 which provides an illustration of a formation subsequent to nitrogen gas creation, the wellbore 100 is within a sandstone formation 108 and a drill pipe 106 is positioned within the wellbore 100. Following a hydraulic fracturing process, fractures 110 exist within the sandstone formation 108. Acid and nitrogen gas generating fluids, such as the treatment fluid of the present disclosure may be injected into the sandstone formation 108 where it migrates within the fractures 110 before produces nitrogen gas, heat, and hydrofluoric acid. The rapidly expanding nitrogen gas causes the microfractures 112 to be created within the formation. The generated microfractures 112 providing pathways for the hydrocarbons trapped within the formation to migrate and be recovered as well as fluid pathways for stimulation of the sandstone formation 108 with the hydrofluoric acid.

The present disclosure includes a variety of methods to provide the treatment fluid deep into a horizontal well before reaction between the constituent components of the treatment fluid is initiated resulting in generation of HF.

In one or more embodiments, the hydrofluoric acid generating precursor, the oxidizing agent, the ammonium containing compound, and the nitrite containing compound are mixed together before being pumped downhole for injection into the sandstone formation as one solution. It will be appreciated that one or both of the hydrofluoric acid generating precursor and the oxidizing agent may be encapsulated with a degradable encapsulation to reduce premature reaction. The treatment solution formed from the hydrofluoric acid generating precursor, the oxidizing agent, the ammonium containing compound, and the nitrite containing compound may remain stable until reaching an elevated temperature experienced downhole.

In further embodiments, the components of the treatment solution may be provided to the sandstone formation as two or more separate solutions. Specifically, a first solution comprising the hydrofluoric acid generating precursor, the oxidizing agent, and the ammonium containing compound and a second solution comprising the nitrite containing compound may be provided downhole separately. The first solution and the second solution are combined downhole to initiate Reaction 1 between the nitrite containing compound and the ammonium containing compound followed by initiation of Reaction 2. It will be appreciated that one or both of the hydrofluoric acid generating precursor and the oxidizing agent may be encapsulated with a degradable encapsulation to prevent premature reaction. In one or more embodiments, the first solution is provided downhole through a coiled tubing of the drilling string and the second solution is provided downhole through an annulus of the drilling string. In one or more embodiments, the first and second solutions are reversed where the second solution is provided downhole through the coiled tubing of the drilling string and the first solution is provided downhole through the annulus of the drilling string.

In one or more embodiments, the components of the treatment solution may be injected or squeezed into the sandstone formation in a sequential manner. The hydrofluoric acid generating precursor and the oxidizing agent may be injected into the sandstone as a first injection and subsequently the nitrite containing compound may be injected into the sandstone formation as a second injections. The ammonium containing compound may be provided as part of the first injection, the second injection, or both injections. For example, NH₄F and NaBrO₃ may be squeezed into the sandstone formation and then subsequently NaNO₂ and NH₄Cl may be provided downhole and squeezed into the sandstone formation. Similarly, NH₄F, NaBrO₃, and NH₄Cl may be squeezed into the formation and subsequently only NaNO₂ is provided downhole and squeezed into the sandstone formation. It will be appreciated that the order may be reversed such that NaNO₂ is initially provided and squeezed into the sandstone formation followed by a solution comprising NH₄F, NaBrO₃, and NH₄Cl. It will be appreciated that one or both of the hydrofluoric acid generating precursor and the oxidizing agent may be encapsulated with a degradable encapsulation to reduce premature reaction.

The location and rate of HF generation may be affected by a variety of process parameters. For example, the pH of the treatment fluid, the downhole temperature and by proxy the temperature of the treatment fluid, and the downhole pressure each affect the reaction rate, the reaction triggering temperature, or both of one or more of the reactions to generate HF downhole.

The downhole pressure at the location of the treatment solution may affect the initiation temperature of Reaction 1. With reference to FIG. 5, the effect of initial pressure on the initiation temperature of Reaction 1 is shown. As the downhole pressure increases the initiation temperature of Reaction 1 generally decreases. However, it will be appreciated that for pressures in excess of approximately 300 pounds per square inch (psi), an increase in pressure does not have a corresponding effect on the initiation temperature of Reaction 1. In various embodiments, the downhole pressure in the reservoir may be 300 to 15000 psi, 500 to 12000 psi, 1000 to 10000 psi, or 3000 to 8000 psi.

The pH of the treatment solution also may affect the initiation temperature of Reaction 1 and Reaction 2. With reference to FIG. 6, the effect of pH on the initiation temperature of Reaction 1 is shown at a reservoir pressure of 500 psi. At that pressure, an increase in the pH results in a corresponding increase in the initiation temperature of Reaction 1. At a pH of 6 the initiation temperature of Reaction 1 is approximately 122° F. (50° C.), at a pH of 8 the initiation temperature of Reaction 1 is approximately 150° F. (65.6° C.), and at a pH of 9 the initiation temperature of Reaction 1 is approximately 182° F. (83.3° C.). As such, the pH of the treatment solution may be adjusted for the specific temperature and pressure conditions of each reservoir to allow for positioning of the treatment solution within the formation before Reaction 1 progresses. In various embodiments, the pH may be in the range of 6 to 10, 6 to 9, 7 to 8, 8 to 9, 6 to 8, or 7 to 9 to account for distinct downhole pressures and temperatures unique to each well.

In another embodiment, at least the ammonium containing compound and the nitrite containing compound of the treatment fluid are provided in an acid generating solution comprising a degradable acid precursor. The acid generating solution may be injected into a sandstone formation or as part of a hydraulic fracturing procedure. The degradable acid precursor may be soluble and compatible with the ammonium containing compound and the nitrite containing compound, and the resulting reaction products. The degradable acid precursor degrades and releases acid within the formation reducing the pH to less than a reaction initiation threshold pH. Specifically, the generated acid reduces the pH of the resulting solution over time such that the injected fluids have time to enter into the formation, and migrate into the fractures created by the hydraulic fracturing process before the pH is reduced to less than the reaction initiation threshold pH. The reaction initiation threshold pH represents the pH at which reaction between the ammonium containing compound and the nitrite containing compound occurs at the present temperature and pressure. In one or more embodiments, the reaction initiation threshold pH is less than about 7.0 for a reservoir pressure of 500 psi and a reservoir temperature of approximately 135° F. (57.3° C.). It will be appreciated that the reaction initiation threshold pH may vary based on the reservoir temperature, the reservoir pressure, or both. Example acid generating precursors include acetates, including methyl acetates and ethyl acetates. At typical formation temperatures of 100 to 350° F., methyl acetate hydrolyzes and releases acetic acid. This takes place inside the formation after injection of the fluids. In certain embodiments, approximately 5% by volume of the acid generating precursor as a 0.1 molar solution may be included with the ammonium containing compound and the nitrite containing compound.

It will be appreciated that the initiation temperature of Reaction 1 is approximately 500° F. (260° C.) at a pH of 10 allowing for triggering progression of Reaction 1 based on adjustments to only the pH. Specifically, at typical formation temperatures of 100 to 350° F., utilization of a treatment solution having an initial pH greater than 10 ensures Reaction 1 does not proceed until the buffer degrades to generate a pH of the treatment solution less than the reaction initiation threshold pH.

In one or more embodiments, at least one of the ammonium containing compound and the nitrite containing compound is encapsulated with a self-degradable coating. The coating provides a temporary barrier between the ammonium containing compound, the nitrite containing compound, or both, such that they are unable to react in accordance with Reaction 1 before degradation of the coating.

The material of the degradable coating and the thickness of the degradable coating each affect the delay in releasing the reactants for Reaction 1 downhole. Specifically, the speed of removal of the degradable coating determines the timing of the availability of both the ammonium containing compound and the nitrite containing compound for reaction. A thicker degradable coating would naturally require a longer period of time in an erosive environment before penetration, dissipation, and removal of the degradable coating from the ammonium containing compound or the nitrite containing compound. Similarly, differing the distinct materials forming the degradable coating would provide different time horizons in each erosive environment before availability of the ammonium containing compound and the nitrite containing compound for reaction in accordance with Reaction 1. Specifically, the water solubility or heat degradation, for example, of carboxymethyl cellulose and polyvinyl alcohol may be distinct allowing for tuning of the time delay before progression of Reaction 1.

Suitable encapsulation materials for the degradable coating of the ammonium containing compound or the nitrite containing compound can include hydrated polymers, such as guar, chitosan, and polyvinyl alcohol. In certain embodiments, the previously noted hydrated polymer encapsulation materials may be used as the encapsulant for the nitrite containing compound, such as sodium nitrite. In alternate embodiments, binders, such as carboxymethyl cellulose or xanthan, can be used as an encapsulant. In certain embodiments, the carboxymethyl cellulose or xanthan may be the encapsulant for the ammonium containing compound, such as ammonium chloride. The heat of the formation, presence of acid, or presence of water may collectively play a role in the erosion or degradation of the encapsulating material, thereby releasing the reactants. It will be appreciated that the degradable encapsulation of one or both of the hydrofluoric acid generating precursor and the oxidizing agent may be of similar nature to that disclosed for the degradable coating of the ammonium containing compound or the nitrite containing compound.

The extent of application of the degradable coating may also affect the progression of Reaction 1. In one or more embodiments, 30 to 100 weight percent (wt. %) of one or more of the ammonium containing compound and the nitrite containing compound are encapsulated. In various embodiments, 40 to 95 wt. %, 50 to 90 wt. %, or 60 to 85 wt. % of one or more of the ammonium containing compound and the nitrite containing compound are encapsulated. The greater the percentage of the one or more of the ammonium containing compound and the nitrite containing compound which are encapsulated, the slower Reaction 1 will progress as the reaction is limited by the availability of reactants. Specifically, when 100 wt. % of one or more of the ammonium containing compound and the nitrite containing compound are encapsulated, the reaction rate of Reaction 1 is limited by the erosion rate of the degradable coating and the commensurate rate of availability of the ammonium containing compound and the nitrite containing compound. Conversely, when 30 wt. % of one or more of the ammonium containing compound and the nitrite containing compound are encapsulated Reaction 1 may progress with 70 wt. % of the reactants and is only limited with the remaining 30 wt. %. It will be appreciated that the degradable encapsulation of one or both of the hydrofluoric acid generating precursor and the oxidizing agent may be provided at a similar weight percentage as that disclosed for the degradable coating of the ammonium containing compound or the nitrite containing compound.

Adjusting the parameters of the degradable coating allows the treatment fluid to be tunable to specific reservoir conditions. A delay as determined by the specific well conditions may be created before availability of reactions for Reaction 1. For example, a delay of 3 to 12 hours may be achieved to allow sufficient time for the treatment fluid to be placed downhole and deep within a horizontal well before generation of HF and associated interaction with the sandstone formation to remove silica and silicate minerals.

The concentration of HF in the sandstone formation affects the rate of silica and silicate mineral removal. The HF dissolves silica and silicate minerals, such as aluminosilicate, while HCl or other strong mineral acid helps keep the reaction products soluble in the spent solution. As the HF is generated in-situ at the site of the sandstone formation the HF does not undergo a potency decrease as a result of interaction with other species during the transfer from the surface to the sandstone formation. In one or more embodiments, the concentration of HF at the sandstone formation is from 0.5 to 10 wt. %. In various further embodiments, the concentration of HF at the sandstone formation is from 0.8 wt. % to 8 wt. %, 0.9 wt. % to 5 wt. %, or 1 wt. % to 3 wt. %.

Generation of HF downhole removes the need for handling HF at the surface of the wellbore allowing for a greater concentration of HF without the associated handling risks. Further, generation of HF in-situ alleviates exposure of the drill string components to the HF during transit downhole allowing for greater concentrations of HF at the sandstone formation without the increased corrosion risks from HF exposure.

Reaction of the HF with the silica and silicate materials results in the HF being spent before flowback into the wellbore. After stimulation operations the resulting slurry of the spent HF and the removed silica/silicate present downhole must be removed from the wellbore. In one or more embodiments, the slurry is squeezed back into the formation for retention and disposal. In further embodiments, the slurry is pumped from the wellbore and flowed to a pit at the surface for retention, processing, and disposal. Any solids generated during the formation stimulation operation may be removed during the stimulation operation through the motive lifting force of generated nitrogen gas produced by the reaction of the nitrite containing compound and the ammonia containing compound in Reaction 1.

The methods and compositions of the present disclosure may also be applied to deep carbonate formation stimulation in hydrocarbon reservoirs. Specifically, in deep carbonate formation stimulation, calcite (CaCO₃) and dolomite (CaMg(CO₃)₂) are removed from the deep carbonate formation to allow flow of trapped hydrocarbon reserves. The calcite and dolomite may be removed with carbonite acidizing where HCl is reacted with the calcite and dolomite. It will be appreciated that Reaction 2 of the present disclosure provides HCl in-situ and thus may be used for deep carbonate formation stimulation. Specifically, the ammonium containing compound, the nitrite containing compound and the oxidizing agent may each be provided to allow Reactions 1 and 2 to progress and generate HCl. In-situ and delayed production of HCl allows for deeper carbonate formation stimulation in each fracture than traditional methods of providing HCl from the surface as the HCl is not fully reacted and spent before reaching deep fractures.

It will be appreciated that the present methods and compositions may simultaneously stimulate sandstone formations and deep carbonate formations in a single procedure. This is advantageous in operations with both sandstone and carbonate formations.

EXAMPLES

Testing was completed to verify the progression of Reaction 2 and generation of HF. An aqueous solution of 0.75 grams (g) sodium bromate and 0.37 g of ammonium fluoride in 25 milliliters (ml) of water was prepared. A similar solution of 0.75 grams (g) sodium bromate and 0.57 g of ammonium bifluoride in 25 milliliters (ml) of water was also prepared. The aqueous solution was placed in a 125 ml autoclave reactor and an initial pH of the aqueous solution was measured. The autoclave reactor was sealed and placed in an oven at 150° C. for 8 hours (h). The autoclave reactor was then cooled to room temperature and a final pH was measured. It was determined that the pH of the aqueous solution dropped to 2-3, whereby acid-base titration results yielded an approximately 8.4 mmol of acid, clearly indicating the formation of acid.

Having demonstrated feasibility of Reaction 2 for the generation of HF, a field test of Reaction 1 for the generation of heat and pressure was completed. Sodium nitrite and ammonium chloride, in accordance with Reaction 1, were pumped separately downhole and into the formation. Specifically, sodium nitrite was pumped through the coiled tubing of the drilling string and ammonium chloride was pumped through the annulus of the drilling string. With reference to FIG. 7, the downhole pressure increased from approximately 2600 psi to approximately 3800 psi after injection of the reactants and initiation of Reaction 1 to generate nitrogen gas (approximately 14:37:47). The pressure was measured with a gauge positioned at the wellhead. Similarly, the downhole temperature increased from approximately 100° F. (37.8° C.) to approximately 420° F. (215.6° C.) after injection of the reactants and initiation of Reaction 1 to generate heat in the exothermic reaction. The temperature was measured with a gauge positioned within the wellbore at the well bottom.

With continued reference to FIG. 7, it is noted that there is an approximately 3 hour delay between injection of the reactants and the spike in temperature. The approximately 3 hour delay is attributed to the experimental protocol where the sodium nitrite and ammonium chloride were continuously squeezed into the formation for the first 3 hours after injection. During the period where the sodium nitrite and ammonium chloride were squeezed into the formation, Reaction 1 was proceeding deep within fractures and microfractures of the formation away from the temperature gauge in the wellbore and as such the temperature gauge was unable to measure the temperature increase of the solution within the formation. Upon completion of the pumping of the fluid with the reactions into the formation, the fluid was able to flow back. The backflowing fluid, having been heated for up to 3 hours by progressing Reaction 1 during the period of squeezing into the formation, returns to the wellbore and the temperature gauge in a hot state.

Upon completion of Reaction 1 to generate heat within the formation, the products and residual reactants were displaced with water pumped into the formation. Upon termination of pumping, flowback occurred from the formation of the heated fluid generating a second peak in temperature in FIG. 7.

It should now be understood the various aspects of the method and associated treatment fluid for stimulating production of hydrocarbons from a sandstone formation are described and such aspects may be utilized in conjunction with various other aspects.

In a first aspect, the disclosure provides a method for stimulating production of hydrocarbons from a sandstone formation. The method comprises the steps of: injecting a stimulation fluid into the sandstone formation, the stimulation fluid comprising a hydrofluoric acid generating precursor and an oxidizing agent, where one or both of the hydrofluoric acid generating precursor and the oxidizing agent comprise a degradable encapsulation; injecting an ammonium containing compound into the sandstone formation; injecting a nitrite containing compound into the sandstone formation; maintaining the stimulation fluid, the ammonium containing compound, and the nitrite containing compound in the sandstone formation. The stimulation fluid, the ammonium containing compound, and the nitrite containing compound are maintained in the sandstone formation to initiate reaction of the ammonium containing compound and the nitrite containing compound to generate heat and nitrogen gas, where upon generation of heat within the formation and degradation of the degradable encapsulation, the hydrofluoric acid generating precursor and the oxidizing agent react to form hydrofluoric acid in-situ, and dissolve silica and silicate minerals to stimulate the sandstone formation.

In a second aspect, the disclosure provides the method of the first aspect, in which the hydrofluoric acid generating precursor comprises NH₄F, NH₄HF₂, or both NH₄F and NH₄HF₂.

In a third aspect, the disclosure provides the method of the first or second aspects, in which the oxidizing agent comprises an agent selected from the group consisting of a peroxide, a persulfate salt, a permanganate salt, a bromate salt, a perbromate salt, a chlorate salt, a chlorite salt, a perchlorate salt, a hypochlorite salt, an iodate salt, a periodate salt, and mixtures thereof.

In a fourth aspect, the disclosure provides the method of the third aspect, in which the oxidizing agent comprises sodium bromate or potassium bromate.

In a fifth aspect, the disclosure provides the method of any of the first through third aspects, in which the nitrite containing compound comprises a nitrite salt.

In a sixth aspect, the disclosure provides the method of the fifth aspect, in which the nitrite salt comprises NaNO₂.

In a seventh aspect, the disclosure provides the method of any of the first through sixth aspects, in which the ammonium containing compound comprises one or more of ammonium hydroxide, ammonium chloride, ammonium bromide, ammonium nitrate, ammonium nitrite, ammonium sulfate, and ammonium carbonate.

In an eighth aspect, the disclosure provides the method of the seventh aspect, in which the ammonium containing compound comprises NH₄Cl.

In a ninth aspect, the disclosure provides the method of any of the first through eighth aspects, in which at least one of the ammonium containing compound and the nitrite containing compound are encapsulated with a degradable coating such that reaction between the ammonium containing compound and the nitrite containing compound is delayed.

In a tenth aspect, the disclosure provides the method of any of the first through ninth aspects, in which a first solution comprising the hydrofluoric acid generating precursor, the oxidizing agent, and the ammonium containing compound and a second solution comprising the nitrite containing compound are provided downhole separately.

In an eleventh aspect, the disclosure provides the method of the ninth aspect, in which the hydrofluoric acid generating precursor, the oxidizing agent, the ammonium containing compound, and the nitrite containing compound are mixed together before being pumped downhole for injection into the sandstone formation as one solution.

In a twelfth aspect, the disclosure provides the method of any of the first through tenth aspects, in which the first solution or the second solution is provided downhole through a coiled tubing of the drilling string and the other of the first solution or the second solution is provided downhole through an annulus of the drilling string.

In a thirteenth aspect, the disclosure provides the method of any of the first through ninth aspects, in which the hydrofluoric acid generating precursor and the oxidizing agent are injected into the sandstone formation as a first injection and subsequently the nitrite containing compound is injected into the sandstone formation as a second injection. The ammonium containing compound is provided with one or both of the first injection and the second injection, thereby activating the reaction of the ammonium containing compound and the nitrite containing compound to generate heat and activate the stimulation fluid to generate hydrofluoric acid in-situ.

In a fourteenth aspect, the disclosure provides the method of the ninth aspect, in which at least one of the ammonium containing compound and the nitrite containing compound is encapsulated in a polymer coating.

In a fifteenth aspect, the disclosure provides the method of any of the first through fourteenth aspects, in which at least one of the hydrofluoric acid generating precursor and the oxidizing agent is encapsulated in a polymer coating.

In a sixteenth aspect, the disclosure provides the method of the thirteenth or fourteenth aspects, in which the polymer coating comprises a hydrated polymer.

In a seventeenth aspect, the disclosure provides the method of the ninth or fourteenth aspects, in which at least 30 percent by weight of one or more of the ammonium containing compound and the nitrite containing compound are encapsulated.

In an eighteenth aspect, the disclosure provides the method of any of the first through seventeenth aspects, in which at least 30 percent by weight of one or more of the hydrofluoric acid generating precursor and the oxidizing agent are encapsulated.

In a nineteenth aspect, the disclosure provides the method of any of the first through eighteenth aspects, in which at least the ammonium containing compound and the nitrite containing compound are provided in an acid generating solution that releases hydrogen ions and reduces the pH of the resulting solution to less than a reaction initiation threshold pH to initiate reaction between the ammonium containing compound and the nitrite containing compound.

In a twentieth aspect, the disclosure provides the method of the nineteenth aspect, in which the reaction initiation threshold pH is 7.0.

In a twenty-first aspect, the disclosure provides the method of the eighth aspect, in which the oxidizing agent and the NH₄Cl react to form HCl.

In a twenty-second aspect, the disclosure provides the method of the twenty-first aspect, in which the method further comprises injecting ammonium bifluoride into the sandstone formation, the ammonium bifluoride reacting with HCl to form HF.

In a twenty-third aspect, the disclosure provides a treatment fluid for use in stimulating sandstone formations. The treatment fluid comprises a stimulation fluid, the stimulation fluid comprising a hydrofluoric acid generating precursor and an oxidizing agent, where one or both of the hydrofluoric acid generating precursor and the oxidizing agent comprise a degradable encapsulation; ammonium-based salt, and a nitrite containing compound. The ammonium containing compound and the nitrite containing compound are operable to react and generate heat and nitrogen gas and the hydrofluoric acid generating precursor and the oxidizing agent react are operable to react to form hydrofluoric acid.

In twenty-fourth aspect, the disclosure provides the treatment fluid of the twenty-third aspect, in which the hydrofluoric acid generating precursor comprises NH₄F, the oxidizing agent comprises sodium bromate, the nitrite containing compound comprises a nitrite salt, and the ammonium containing compound comprises one or more of ammonium hydroxide, ammonium chloride, ammonium bromide, ammonium nitrate, ammonium nitrite, ammonium sulfate, and ammonium carbonate.

In a twenty-fifth aspect, the disclosure provides the treatment fluid of the twenty-third or twenty-fourth aspects, in which at least one of the ammonium containing compound and the nitrite containing compound are encapsulated with an degradable coating such that reaction between the ammonium containing compound and the nitrite containing compound is delayed.

In a twenty-sixth aspect, the disclosure provides the treatment fluid of any of the twenty-third through twenty-sixth, in which the treatment fluid additionally comprises ammonium bifluoride.

It should be apparent to those skilled in the art that various modifications and variations can be made to the described embodiments without departing from the spirit and scope of the claimed subject matter. Thus, it is intended that the specification cover the modifications and variations of the various described embodiments provided such modifications and variations come within the scope of the appended claims and their equivalents.

The singular forms “a”, “an” and “the” include plural referents, unless the context clearly dictates otherwise.

Throughout this disclosure ranges are provided. It is envisioned that each discrete value encompassed by the ranges are also included. Additionally, the ranges which may be formed by each discrete value encompassed by the explicitly disclosed ranges are equally envisioned.

As used in this disclosure and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

As used in this disclosure, terms such as “first” and “second” are arbitrarily assigned and are merely intended to differentiate between two or more instances or components. It is to be understood that the words “first” and “second” serve no other purpose and are not part of the name or description of the component, nor do they necessarily define a relative location, position, or order of the component. Furthermore, it is to be understood that that the mere use of the term “first” and “second” does not require that there be any “third” component, although that possibility is contemplated under the scope of the present disclosure. 

What is claimed is:
 1. A treatment fluid for use in stimulating sandstone formations, the treatment fluid comprising: a stimulation fluid, the stimulation fluid comprising a hydrofluoric acid generating precursor and an oxidizing agent, where one or both of the hydrofluoric acid generating precursor and the oxidizing agent comprise a degradable encapsulation; ammonium-based salt; and a nitrite containing compound; where the ammonium-based salt and the nitrite containing compound are operable to react and generate heat and nitrogen gas and the hydrofluoric acid generating precursor and the oxidizing agent react are operable to react to form hydrofluoric acid.
 2. The treatment fluid of claim 1, where the hydrofluoric acid generating precursor comprises NH₄F, NH₄HF₂, or both NH₄F and NH₄HF₂, the oxidizing agent comprises sodium bromate, the nitrite containing compound comprises a nitrite salt, and the ammonium-based salt comprises one or more of ammonium hydroxide, ammonium chloride, ammonium bromide, ammonium nitrate, ammonium nitrite, ammonium sulfate, and ammonium carbonate.
 3. The treatment fluid of claim 2, where the oxidizing agent comprises sodium bromate
 4. The treatment fluid of claim 2, where the nitrite containing compound comprises NaNO₂.
 5. The treatment fluid of claim 2, where the ammonium containing compound comprises NH₄Cl.
 6. The treatment fluid of claim 2, where the hydrofluoric acid generating precursor comprises NH₄F.
 7. The treatment fluid of claim 2, where the hydrofluoric acid generating precursor comprises NH₄F, the oxidizer comprises sodium bromate, the nitrite containing compound comprises NaNO₂, and the ammonium containing compound comprises NH₄Cl.
 8. The treatment fluid of claim 1, where the oxidizing agent comprises an agent selected from the group consisting of a peroxide, a persulfate salt, a permanganate salt, a bromate salt, a perbromate salt, a chlorate salt, a chlorite salt, a perchlorate salt, a hypochlorite salt, an iodate salt, a periodate salt, and mixtures thereof.
 9. The treatment fluid of claim 1, where at least one of the ammonium-based salt and the nitrite containing compound are encapsulated with a degradable coating such that reaction between the ammonium containing compound and the nitrite containing compound is delayed.
 10. The method of claim 9, where at least 30 percent by weight of one or more of the ammonium containing compound and the nitrite containing compound are encapsulated.
 11. The treatment fluid of claim 2, where the treatment fluid additionally comprises ammonium bifluoride.
 12. The treatment fluid of claim 1, where the oxidizing agent is present in the stimulation fluid at a concentration in the range of 1.0 M to 4.0 M.
 13. The treatment fluid of claim 9, where the degradable coating comprises a hydrated polymer.
 14. The treatment fluid of claim 13, where the hydrated polymer comprises guar, chitosan, or polyvinyl alcohol.
 15. The treatment fluid of claim 9, where the degradable coating comprises carboxymethyl cellulose.
 16. The treatment fluid of claim 9, where the degradable coating comprises xanthan.
 17. The treatment fluid of claim 1, where the degradable encapsulation comprises a hydrated polymer.
 18. The treatment fluid of claim 1, where the degradable encapsulation comprises carboxymethyl cellulose.
 19. The treatment fluid of claim 1, where the degradable encapsulation comprises xanthan.
 20. The treatment fluid of claim 17, where the hydrated polymer comprises guar, chitosan, or polyvinyl alcohol. 